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# Journal of the Air & Waste Management Association
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# Emissions of Sulfur Trioxide from Coal-Fired Power Plants

R.K. Srivastava a

### , C.A. Miller a

### , C. Erickson b

### & R. Jambhekar b

a

### Office of Research and Development, National Risk Management Research Laboratory, Air Pollution Prevention and Control Division , U.S. Environmental Protection Agency , Research Triangle Park , North Carolina , USA

b

### Babcock Borsig Power, Inc , Worcester , Massachusetts , USA Published online: 22 Feb 2012.

To cite this article: R.K. Srivastava , C.A. Miller , C. Erickson & R. Jambhekar (2004) Emissions of Sulfur Trioxide from Coal-Fired Power Plants, Journal of the Air & Waste Management Association, 54:6, 750-762, DOI: 10.1080/10473289.2004.10470943

To link to this article: http://dx.doi.org/10.1080/10473289.2004.10470943

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# Emissions of Sulfur Trioxide from Coal-Fired Power Plants

**R.K. Srivastava and C.A. Miller** Office of Research and Development, National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina

**C. Erickson and R. Jambhekar** Babcock Borsig Power, Inc., Worcester, Massachusetts

ABSTRACT Emissions of sulfur trioxide (SO 3 ) are a key component of plume opacity and acid deposition. Consequently, these emissions need to be low enough to not cause opacity violations and acid deposition. Generally, a small fraction of sulfur (S) in coal is converted to SO 3 in coal-fired combustion devices such as electric utility boilers. The emissions of SO 3 from such a boiler depend on coal S content, combustion conditions, flue gas characteristics, and air pollution devices being used. It is well known that the catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of sulfur dioxide in the flue gas to SO 3 . The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO 3 and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacity and undesirable emissions. Recently, such effects have been observed at plants firing high-S coal and equipped with SCR systems and wet scrubbers. This paper investigates the factors that affect acidic mist production in coal-fired electric utility boilers and discusses approaches for mitigating emission
of this mist.

INTRODUCTION As understanding of the adverse effects of air pollution has grown, so also has the complexity of coal-fired power plant design and operation, especially with regard to airpollution control systems. Control of air pollutant emissions is not only a legal requirement but also is becoming a financial necessity, as salability of effluents and tradingof emissions increase the direct monetary value of emissions control. The days when one must only consider the nuisance value of fly ash are long past. 1As plant complexity has increased, so have unexpected consequences of changing segments of the total chemical process that occurs between fuel preparationand ultimate emissions. One of the more discernible adverse consequences is the formation and emission of sulfur trioxide (SO 3 )/sulfuric acid (H 2 SO 4), as highlighted by the recent and well-publicized experiences of a power plant in Ohio. 2 Although not directly subject to emission limits, SO 3 is important to consider during the design and operation of coal-fired utility boilers for a number of environmental and plant performance reasons. The formation of SO 3 will occur during the combustion of sulfur (S)-bearing fuels such as coal and heavy fuel oils. Virtually all of the SO 3 converts to H 2 SO 4 as flue gasis cooled in the air preheater (APH). Relatively high concentrations of SO 3 /H 2 SO 4 in the boiler, stack, or plume can cause adverse impacts to plant equipment and to the environment. Impacts on plant equipment can includecorrosion, fouling, and plugging and may require additional hardware or changes in operation to minimize SO 3 /
H 2 SO 4 concentrations and the resulting adverse impacts.

Health and Environmental Effects Formation of visible H 2 SO 4 droplets depends upon the concentration and dew point of H 2 SO 4 and the IMPLICATIONS Formation and emissions of SO 3/H 2 SO 4 can potentially lead to plant operation-related problems and environmental concerns. The emissions of SO 3 from a boiler depend on a number of interacting complex factors including coal sulfur content, combustion conditions, flue gas characteristics, and air pollution devices being used. Understanding the paramenters leading to excessive generation of SO 3/H 2 SO 4emissions can assist in selection of practical control approaches. This paper investigates the factors that affect SO 3/H 2 SO 4 emissions from coal-fired electric utility boilers and discusses approaches for mitigating these emissions. The paper is expected to be a state-of-the-art reference on the subject for regulators, utility industry personnel, and
others stakeholders. 

### TECHNICAL PAPER ISSN 1047-3289 J. Air & Waste Manage. Assoc. 54 :750–762

Copyright 2004 Air & Waste Management Association

750 Journal of the Air & Waste Management Association Volume 54 **June 2004**concentration of sub-micron particles upon which the acid can condense. As seen in Figure 1, H 2 SO 4 dew point is a function of water vapor and H 2 SO 4 concentration and
increases as both these variables increase. 3 The curves in Figure 1 determine the fraction of H 2 SO 4 in the vapor and condensed phases for temperatures below the dew point. For example, a 250 ° F flue gas with 10% water vapor and 8 ppm H 2 SO 4 will have a vapor-phase acid gas concentra

tion of

 2 ppm, with the remaining 6 ppm in the condensed phase. If temperatures at the stack are low enough and water vapor and H 2 SO 4 concentrations are high enough, the condensed-phase concentration of H 2 SO 4 can be at a level that results in the formation of a visible plume attached to the stack. Once the gases leave the stack, the rate of cooling and subsequent H 2 SO 4 condensation competes with the plume dilution by entrainment of ambient air into the plume. Even in cases where stack conditions are
such that the H 2 SO 4 is completely in the vapor phase at the stack exit, a detached plume may still form shortly downwind as temperatures drop below the dew point. In most cases, and particularly in the case where
H 2 SO 4 , water, and sub-micron solid particles are present, condensation is the dominant formation mechanism. The opacity of these plumes is most strongly in fluencedby the concentrations of condensing species and submicron fly ash particles present in the stack gases. The size distribution of the sub-micron fly ash also can have a noticeable effect on plume opacity at low to moderate
H 2 SO 4 concentrations, because these particles act as con

densation sites for the condensing vapor-phase H 2 SO 4 .The relationship between sub-micron particle concentration, H 2 SO 4 concentration, and plume opacity is shown in Figure 2 for flue gas with a sub-micron particle mode at
0.15 m diameter. 4,5 The gray area denotes a typical range of sub-micron particle concentrations downstream of an electrostatic precipitator (ESP). 6 The curves in Figure 2 illustrate that H 2 SO 4 concen

tration can have a strong impact on opacity when fi neparticle concentrations are present at realistic levels. Because the condensing acid particles can nucleate to formparticles even at very low levels of pre-existing submicron particles, further reduction of sub-micron solid particles may not signi fi cantly reduce plume opacity. As an example, a unit emitting 16 ppm of vapor-phase
H 2 SO 4 and 5 mg/m 3 of sub-micron particles is predicted to result in a plume opacity of

 35%. An opacity of 20%can be achieved by reducing sub-micron PM concentration to
 1.6 mg/m 3 (i.e.,

 70% reduction) or by reducing
H 2 SO 4 to  8 ppm (a 50% reduction). For units with limited ability to further reduce PM emissions, control of
SO 3 (and, subsequently, H 2 SO 4) may be the only viable option for meeting plume-opacity requirements. Because essentially all the SO 3 is converted to H 2 SO 4 at or below stack temperatures, Figure 2 also illustrates the impact of
increases in SO 3 formation on plume opacity. A unit with 1 mg/m 3 of sub-micron particles in the stack gases is predicted to experience doubling of plume opacity from

 5 to 10% when H 2 SO 4 concentrations increase from 5 to 10 ppm. Data on direct adverse effects on human health are inconsistent, but studies indicate that aqueous acidicaerosols at typical and even elevated ambient concentrations generally have minimal effects on symptoms andmechanical lung function in young healthy adults. However, there are studies that have shown changes in mucociliary clearance and modest bronchoconstriction in asthmatics exposed to elevated concentrations of 400 g/m 3

or more. 7,8 Of more concern than the effects of exposure Figure 1. Dew point of H 2 SO 4 as a function of H 2 SO 4 concentration for different water vapor concentrations. 3 Figure 2. Iso-opacity plot calculated for a bimodal distribution of coarse and sub-micron particles. The sub-micron particle mode is at
0.15 m diameter. 5 The gray area represents typical sub-micron mass concentrations in the stack of a coal-fired utility boiler. 6 

### Srivastava, Miller, Erickson, and Jambhekar

Volume 54 **June 2004** Journal of the Air & Waste Management Association 751to typical ambient levels of SO 3 /H 2 SO 4 aerosol alone is exposure to this aerosol mixed with other ambient PM constituents, including elemental carbon and metals. 9 In situations where SO 3 /H 2 SO 4 aerosol combines with a sinking plume, the ambient concentrations near the stack can reach signi fi cantly higher levels than thosenormally experienced. In such cases where meteorological and operating conditions combine to form a nearstack acidic fog, damage to property and vegetation can occur if the conditions are sustained for an extended period. Anecdotal evidence of adverse health impacts, such as burning eyes, sore throats, and headaches, has also been reported in such cases. 2

Impacts on Plant HardwareThe most common problem associated with elevated concentrations of SO 3 is low-temperature (  300 ° F [150 ° C])
corrosion. 10 Once formed, SO 3 reacts easily with the mois

ture in combustion flue gases to produce H 2 SO 4 . Below its dew point, H 2 SO 4 condenses and will collect in relatively low-temperature areas of the flue gas path, such as the air heater, and corrode the contacted metal components. The dew point varies with H 2 SO 4 and water concentrations in
the flue gas (see Figure 1), but is typically between 200 and
300 ° F (95 and 150 ° C, respectively), corresponding to low (8%) moisture, low (0.1 ppm) H 2 SO 4 conditions and high (15%) moisture, high (20 ppm) H 2 SO 4 conditions, respec

tively. At higher temperatures (above 1000 ° F [540 ° C]),
SO 3 can cause corrosion in superheaters and reheaters. 11 These high-temperature reactions are less common thanthe low-temperature condensation and corrosion reactions. In addition to forming corrosive H 2 SO 4 , SO 3 reacts to form sulfate (SO 4 2

 ) particles, especially ammonium sulfate [(NH 4) 2 SO 4] and ammonium bisulfate (NH 4 HSO 4), in boilers using ammonia (NH 3 ), which can lead to foul

ing or plugging of APH passages. 12 Regular maintenance is conducted at plants to address the impacts described. This maintenance can include monitoring and replacement of materials, washing of APH passages, and other activities. In some cases, modi fi cation or addition of hardware may be required to minimize corrosion or plugging. At plants using wet flue gas desulfurization (FGD) systems,
the reduction in flue gas temperature can result in increased H 2 SO 4 condensation and subsequent corrosion. In such cases, the flue gas may require reheating to ensureit remains above the dew point, thereby resulting in increased operation costs. 13

REGULATORY OVERVIEW There are currently no U.S. regulations that directly limit emissions of SO 3 /H 2 SO 4 aerosols from utility boilers. Other regulatory programs may, however, require SO 3 control, as discussed later. German emission standards limit the combined sulfur dioxide (SO 2) and SO 3 emission concentrations to a daily average of 50 mg/Nm 3 and a 30-min average of 200 mg/Nm 3 . There is no separate emission limit for SO 3 alone. 14 In the United States, SO 3 emissions are included as part of limits on opacity and particulate matter (PM) emissions, and H 2 SO 4 is listed as a hazardous air pollutant (HAP) under Title III of the Clean Air Act Amendments of
1990. 15 Under Title III, electric utility generating stations are exempt from the mass emission limits of 10 t (9.09 tonnes) per year of any single HAP or 25 t (22.7 tonnes) per year of combined HAPs set for other industrial sources. Thus, although H 2 SO 4 is a listed HAP and is emitted in signi fi cant quantities by coal- fi red utility generating stations, 16 there is no regulatory requirement to control these emissions as HAPs. They must, however, be reported to the U.S. Environmental Protection Agency(EPA) under the Toxics Release Inventory (TRI) requirements. The H 2 SO 4 is typically measured and reported as equivalent SO 3 . EPA has de fi ned primary PM as particles that are either emitted directly as a solid or liquid or are emitted as a vapor but condense or react upon cooling and dilution in the ambient air to form solid or liquid PM immediately after discharge from the stack. 17 Secondary PM is composed of particles that form through chemical reactions in the ambient air well after dilution and condensation have
occurred. 18 Under this de fi nition, SO 3 or H 2 SO 4 that is in the vapor phase in the furnace or stack and either reacts to
form SO 4 2

 particles or condenses to form liquid H 2 SO 4 immediately after leaving the stack is considered part of primary PM emissions and is therefore subject to PM
emission limits. In some states or localities, plants may be required to
control SO 3 to maintain opacity standards. Even thoughopacity measurements in the stack may be within regulatory limits, the formation of a visible plume caused by the presence of SO 3 may result in plume opacities higher than
allowable levels and a need to control SO 3 emissions. Most states have a 20% opacity limit for stationary sources, including coal- fi red utility boilers, and many also have provisions for higher opacity levels during unit startup. There are some exceptions to the 20% limit, with a few states having opacity limits of 40% and at least one (West Virginia) with a 10% opacity limit. The formation of a detached plume is indicated when in-stack opacity measurement values are lower than thosein the downwind plume. While in-stack opacity measurements are made using continuous emission monitors,measurements of the downwind plume opacity are covered under EPA Method 9. 9 The increase in opacity from in-stack measurements to downwind is often caused by the condensation of vapors such as H 2 SO 4 and can result 

### Srivastava, Miller, Erickson, and Jambhekar

752 Journal of the Air & Waste Management Association Volume 54 **June 2004**in regulatory violations and good neighbor policy concerns.

FORMATION OF SO 3 Formation in the Boiler The S in coal has inorganic and organic components. The inorganic component is predominantly pyrite, which can exist both as distinct particles (excluded) and bound in the coal matrix (included). The organic component is part of the various organic structures present in coal. The fractions of included and excluded pyrite and organiccomponent delivered to a furnace are known to be dependent on the fi neness to which the coal is ground. During the combustion of coal, virtually all the S gets oxidized to gaseous species such as SO 2 and SO 3 , with SO 2 being the principal oxide. Although detailed chemical mechanisms for oxidation of fuel S are not understood well at present, it is believed that this oxidation proceeds through rapid
formation of SO 2, occurring on a timescale comparable to that of fuel oxidation reactions. Because SO 2 formation isso rapid, its concentration can be estimated using equilibrium calculations. The primary reaction that results in SO 3 formation in
fl ames is

SO 2  O  M 3 SO 3  M (1)

This recombination reaction proceeds rapidly near the combustion zone in the presence of super-equilibrium concentrations of oxygen (O) atoms. The consumption of
SO 3 near fl ames occurs primarily via

SO 3  HO 2 3 HOSO 2  O 2 (2)

and

SO 3  O 3 SO 2  O 2 (3)

A few other reactions are considered to result in formation and destruction of SO 3 near the fl ame zone, but the effect of these on SO 3 concentrations is relatively minor. Table 1 summarizes the reactions involving SO 3 in the combus

tion zone. 19 To understand SO 3 formation, calculations were made using the S chemistry described previously with gas compositions and temperature-time history characteristic of a coal- fi red boiler. 20 This history is shown in Figure 3. Initial gas-phase compositions are assumed to result from complete combustion (with 10 and 30% excess air) of aMontana sub-bituminous and a Western Kentucky bituminous coal. The sub-bituminous coal is composed of 53.26% (by weight) carbon (C), 3.35% hydrogen (H), 0.87% nitrogen (N), 0.78% S, 9.34% ash, 21.23% water, and 11.16% O. The bituminous coal contains 69.79% C, 4.79% H, 1.34% N, 2.95% S, 7.47% ash, 5% water, and8.65% O. The initial compositions resulting from complete combustion of the coals are then equilibrated at
1647 ° C (1900 K) to provide the input composition for the chemical kinetic calculations based on the S chemistry.
Note that the H 2 -O 2 -carbon monoxide (CO) subset of the hydrocarbon mechanism given in ref 21 is used in these calculations. This subset includes 25 reactions involving 11 species. Figures 4 and 5 plot SO 3 mole fraction and the ratio
SO 3 mole fraction/SO 2 mole fraction versus time, respec

tively. Because reaction 1 is exothermic, little SO 3 is formed initially at high temperatures in the furnace. As
the flue gas cools, SO 3 is produced, and the rate of pro

duction is high in the convective region of the boiler (see Figures 3 and 4). SO 3 production via gas-phase S kinetics is complete before the flue gas enters the economizer. The
results also re fl ect that SO 3 production increases with coal Table 1. The reactions involving SO 3 in the combustion zone. The rate constants
are listed in the form k  AT  exp(

 E A / RT ) with units in mol-cm-sec.

Reaction A  E A /R

SO 3  H  HOSO  O 2.5e05 2.92 25,300
SO 3  O  SO 2  O 2 2.0e12 0 10,000
SO 3  SO  SO 2  SO 2 1.0e12 0 5000
SO 2  O  M  SO 3  M 9.2e10 0 1200
SO 2  OH  SO 3  H 4.9e02 2.69 12,000
HOSO 2  SO 3  H 1.4e18

 2.91 27,600
HOSO 2  O  SO 3  OH 5.0e12 0 0
HOSO 2  OH  SO 3  H 2 O 1.0e12 0 0
HOSO 2  O 2  SO 3  HO 2 7.8e11 0 330

Figure 3. Temperature-time history for a coal- fi red power plant. 20 

### Srivastava, Miller, Erickson, and Jambhekar

Volume 54 **June 2004** Journal of the Air & Waste Management Association 753S content and furnace excess air level. This is because
increases in the S content of coal or furnace excess airlevel result in a corresponding increase in the concentration of SO 2 and/or O, which, in turn, results in greater production of SO 3 via reaction 1. Finally, Figure 5 re fl ects that SO 2 conversion rate (i.e., SO 3 /SO 2 molar ratio) for themodeled coals ranges between 0.1 and 0.65%, approximately, and is relatively independent of coal type at a speci fi c excess air level. Because boilers are operated with between 10 and 30% excess air, a 0.65% conversion of
coal S to SO 3 should provide a conservative estimate of
SO 3 production in the furnace.
In addition to the SO 3 formation in the furnace dis

cussed above, additional formation takes place in the temperature range of 1100

– 800 ° F (593

– 427 ° C) found inthe economizer region of the boiler. This formation results from oxidation of SO 2 via molecular oxygen (O 2) catalyzed by iron oxides present in both ash and tube
surfaces. 22 This oxidation mechanism depends on several operating and design parameters, including SO 2 concen

tration, ash content and composition, convective passsurface area, gas and tube surface temperature distributions, and excess air level. Because the impact of these parameters depends on site-speci fi c factors (e.g., cleanliness of tube surfaces), it is diffi cult to characterize the extent of SO 3 formation caused by catalytic oxidation of
SO 2 . A laboratory study found that conversion of SO 2 to
SO 3 in the presence of fly ash ranged between

 10 and 27% for temperatures between 500 and 700 ° C, and essentially increased linearly with the iron oxide content of
the ash. 23 These conversion rates are substantially higher
than those found in coal- fi red boilers, for which data suggest furnace/economizer conversion to be

 0.8 to
1.6% for bituminous and 0.05

– 0.1% for sub-bituminous
coals. 24 The above laboratory study results indicate thattemperatures and residence times greater than, and carbon ash contents lower than, those typically found in
coal- fi red utility boilers are required to achieve high oxidation rates.

Formation of SO 3 in SCR Reactors The SCR technology is increasingly being used at power plants to control emissions of oxides of nitrogen (NO
x). In the SCR process, NH 3 is injected into the flue gas within a temperature range of

 600

– 750 ° F (315

– 400 ° C), upstream of a catalyst. Subsequently, as the flue gas contacts the SCR catalyst, NO
x, which predominantly is nitric ox

ide (NO) in combustion devices, is chemically reduced to molecular nitrogen (N 2). In the most commonly used SCR Figure 4. SO 3 produced during coal combustion. 

### Srivastava, Miller, Erickson, and Jambhekar

754 Journal of the Air & Waste Management Association Volume 54 **June 2004**process layout, known as hot-side SCR, the catalyst is
located between the economizer and the APH. It is well known that the catalyst used in the SCR technology oxidizes a small fraction of SO 2 in the flue gas to SO 3 : 25

–29

SO 2  1 ⁄ 2 O 2 3 SO 3 (4)

The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Generally, this oxidation can range from 0.25 to 0.5% of SO 2 in bitumi

nous and from 0.75 to 1.25% in low-S sub-bituminous coal applications. To examine what this oxidation means, consider an SCR application with an SO 2 oxidation guar

antee of 0.5%. Also assume that the concentrations of SO 2 and SO 3 in the flue gas at the inlet of the SCR reactor are 2000 and 20 ppm, respectively. Then, based on oxidation across the catalyst, the concentrations of SO 2 and SO 3 at the exit of the SCR reactor will be 0.995  2000  1990 ppm and 2000

 1990  20  30 ppm, respectively. Thus,
the SO 3 loading in the flue gas at the exit of the SCR
reactor will be 50% more than that at the inlet. This example illustrates that the level of oxidation across the catalyst can have a signi fi cant impact on SO 3 concentra

tion. In general, for a given catalyst material experiencing
the same flue gas conditions, the oxidation rate of SO 2 to SO 3 (or conversion rate) is inversely proportional to area velocity (AV), which is simply the ratio of flue gas volumetric fl ow rate to geometric catalyst surface area. This implies that the conversion rate is proportional to catalystvolume (and, hence, geometric surface area) and gas residence time in the catalyst. Thus, the conversion rate,
, can be expressed as

 K /AV (5)

where the constant of proportionality, K, is a function of catalyst material and design as well as flue gas properties; 30 that is,

K  f(catalyst material, catalyst design,
flue gas properties) (6) Figure 5. SO 3 conversion during coal combustion. 

### Srivastava, Miller, Erickson, and Jambhekar

Volume 54 **June 2004** Journal of the Air & Waste Management Association 755A systematic study of oxidation of SO 2 to SO 3 over hon

eycomb SCR catalysts has been reported in ref 31. The
fi ndings of this study are as follows: (1) The conversion rate depends primarily on the vanadium content of the catalyst and, therefore, can be controlled by adjusting this content; (2) The oxidation reaction is considerably slower
than diffusion of SO 2 within the pores of thecatalyst. Therefore, the entire volume of the catalyst is active in oxidation of SO 2 to SO 3 in con

trast to reduction of NO
x to N 2, which, being diffusion-limited, occurs mainly at the catalystsurface. The rate of oxidation is linearly proportional to catalyst wall thickness. Accordingly, reducing the wall thickness should not affect NO
x reduction but should reduce SO 2 to SO 3 conver

sion; (3) The reaction rate is of variable order in SO 2 con

centration, increases with temperature, is independent of concentrations of O 2 and water in practical applications, is strongly inhibited by
NH 3 and is slightly enhanced by NO
x .

SO 3 DEPLETION OR CONVERSION TO H 2 SO 4 Processes in APHs Utility boilers use APHs to transfer heat from hot flue gas exiting the economizer to combustion air fl owing into the boiler. These APHs are available in rotary regenerative andtubular designs, with the former used more widely. Typically, the flue gas temperature at the APH inlet is between
600 and 700 ° F (316 and 371 ° C) and

 300 ° F (149 ° C) at
the exit. SO 3 is hygroscopic and, therefore, absorbs vaporphase moisture at temperatures above its dew point to
form H 2 SO 4 vapor. 22 This process occurs in the APH. The extent of conversion of SO 3 to H 2 SO 4 depends on the temperature distribution in the APH and flue gas moisture content. However, virtually all SO 3 converts to H 2 SO 4 at temperatures of 400 ° F or less. If local metal temperatures
in the APH fl ow passages drop below the acid dew point,
some H 2 SO 4 condenses on these surfaces as liquid drop

lets (aerosol). This rate of condensation is dependent on the wall temperature and H 2 SO 4 concentration in the flue gas. In a regenerative APH, where fl ow passages are periodically exposed to hot flue gas and relatively cold incoming combustion air, evaporation of condensed H 2 SO 4 oc

curs on exposure to air. The rate of this evaporation isdependent on the moisture content of air and metal surface temperature of the APH fl ow passage. 32,33 Results of an extensive fi eld test program indicate
that

 40% of the flue gas SO 3 present at the regenerativeAPH inlet is removed in the APH by the condensationevaporation mechanism discussed above. 34 The tubular APH design does not have surfaces that are periodically exposed to combustion air; except for small leakages in welds and seal, no mixing of the flue gas and combustion air occurs. Therefore, the resultant H 2 SO 4 formed is not removed by evaporation into the combustion air andpasses directly out of the APH. Modeling of the acid condensation phenomenon in tubular APHs is described in ref 35. In addition to the condensation-evaporation of SO 3 discussed above, an additional conversion process takes place in boilers using SCR. In such applications, NH 3 is injected as a reagent in the SCR process. A minor fraction,
2

–5 ppmv, of injected NH 3 slips past the SCR catalyst and
does not react with NO
x . This fraction of NH 3 , known as
NH 3 slip, reacts with SO 3 downstream of the SCR reactor and forms (NH 4) 2 SO 4 and NH 4 HSO 4 salts and, thereby, results in removal of SO 3 from the flue gas. 12 This salt formation can be detrimental to the APH performance if APH passages become plugged and pressure loss across the APH results in forcing offl ine washing. The amount and type of salt formed will depend on the amount of NH 3 slip; based on typical concentrations of SO 3 and H 2 O in
flue gas, the amount of NH 3 slip is the limiting factor in salt-formation reactions.

Localized Condensation of H 2 SO 4 in the Duct
between APH and PM Control Condensation of H 2 SO 4 also can take place in the duct
between the APH and the PM control device. 35,36 For example, because of the rotating heat transfer element employed in the regenerative APH, gas fl ow strati fi cation across the fl ow cross-section at the APH inlet is enhanced in the APH. As a result, strong transverse variations in gas temperature and H 2 SO 4 vapor concentration can exist in the gas leaving the APH. These variations can lead to localized condensation of H 2 SO 4 . Based on operating con

ditions, localized condensation also can occur in units using tubular APHs. For a given combination of flue gas H 2 SO 4 concentration and moisture content, Figure 1 can be used to determine if condensation is occurring.

Fly Ash Adsorption and Removal of H 2 SO 4 in PM Control Equipment In addition to the processes described, some H 2 SO 4 gets adsorbed on fly ash in the APH and downstream equipment. The rate of this adsorption depends on the temperature of the flue gas, concentration of H 2 SO 4 , and fly ash properties, in particular alkalinity. 23,37 The adsorption may increase rapidly as the flue gas reaches the cold end of the APH and may continue in the duct between the APH and the PM control equipment. The adsorbed H 2 SO 4 gets removed with the fly ash in the PM control device (ESP or baghouse). 

### Srivastava, Miller, Erickson, and Jambhekar

756 Journal of the Air & Waste Management Association Volume 54 **June 2004**The fi ring of sub-bituminous coals, which generally have S contents on the order of 0.5%, results in fly ash with a relatively high amount of alkali (20

–30% by weight). Such alkaline ash adsorbs virtually all H 2 SO 4 in the flue gas. 38 In such cases, SO 3 injection is required for improving ESP performance. In contrast, based on fly ash properties and temperature, the majority of SO 3 in flue gas of a bituminous coal- fi red boiler may or may not be
adsorbed in fly ash. 30 Finally, hot-side ESPs operate at high-enough temperatures where little adsorption of
H 2 SO 4 occurs. As mentioned above, adsorption of H 2 SO 4 on fly ash depends on the alkalinity of the fly ash and the concentration of H 2 SO 4 . Figure 6 illustrates the general adsorption characteristics of fly ash as a function of the molar ratio of alkali content of fly ash and SO 3 concentration at the inlet of the APH. The alkali content of fly ash is
de fi ned as the molar sum of magnesium oxide (MgO) and calcium oxide (CaO) in the ash. This figure represents a correlation of data from Babcock Borsig Power fi eld-testing programs concerning SO 3 production and capture in
flue gas systems.

Aerosol Formation in Wet FGD Systems
As the H 2 SO 4 vapor-containing flue gas passes through a wet FGD system, it is rapidly cooled below the acid dew point. Because the rate of this cooling is greater than the rate of absorption of H 2 SO 4 vapor in the scrubber solu

tion, the dew-point crossover results in H 2 SO 4 mist with sub-micron droplets. 30,39 In a wet scrubber, generally, the mass transfer between this mist and the scrubbing liquid occurs through inertial impaction, gravitational settling, Brownian diffusion, diffusiophoresis, and thermophoresis. For sub-micron mist droplets with diameters less than

 0.05 m, Brownian diffusion is known to be the primary component of mass transfer. 40 In practical situations, depending on the relative velocity between the sub-micron mist droplets and the collecting liquid form (droplets, wetted walls, liquid sheets, and bubbles), the Brownian motion-induced mass transfer is often not adequate to result in high-effi ciency capture of sub-micron droplets. Therefore, generally, larger droplets in the mist can be removed in the scrubber, but a signi fi cant portion of the sub-micron droplets are not removed and are emitted from the stack. This explains why wet FGD systems are relatively ineffi cient in removing SO 3 /H 2 SO 4 . In general,

 50% of the H 2 SO 4 entering the scrubber may be re

moved in the scrubber.

MEASUREMENT OF SO 3 The controlled condensation system (CCS) has been used since the 1960s for the measurement of SO 3 and H 2 SO 4 in
flue gas streams. 41,42 The general arrangements of the CCSand thimble holder are shown in Figures 7 and 8, respectively. The measurement system consists of a quartz-lined heated probe that draws gas through a quartz thimble for the removal of PM. The probe and thimble are heated to avoid condensation of SO 3 vapor in the gas sample. The gases enter a temperature-controlled condenser where the
SO 3 is condensed on the wall to be collected and mea

sured after the sample run via a deionized water rinse. The measurement techniques for SO 3 and H 2 SO 4 re

cently have been under review for accuracy and improvement for TRI reporting. Recently, a review and veri fi cation project has been undertaken by EPRI to qualify the CCS method and compare fi eld data with available

Figure 6. Fly ash SO 3 capture rate downstream of furnace. 

### Srivastava, Miller, Erickson, and Jambhekar

Volume 54 **June 2004** Journal of the Air & Waste Management Association 757prediction methods used to estimate SO 3 emissions for TRI reporting. 37 The EPRI project compared laboratory
data with fi eld test data for a variety of coals with a range
of S and fly ash chemical compositions. The study further investigated the SO 3 removal rates and effi ciencies of the plant equipment used for fi eld veri fi cation. The EPRI project has concluded that alkaline ash will produce a bias in the SO 3 measurement. The bias is a result of SO 3 removal in the thimble holder by the alka

line ash collected on the quartz thimble. This bias is seen as signi fi cant for low-S, high-alkaline ash fuels (Powder River Basin coals). The CCS was found to have a bias of
20

–25% low readings for high S, acidic ash fuels and greater than 40% for Powder River Basin coals. A possible solution to the bias is utilized in Europe. 43 The test method uses a system similar to the CCS; however, the quartz thimble is replaced with a small tubular ESP. The tubular ESP removes the ash to the sidewalls away from the gas stream; in contrast, the quartz thimble fi lters the
flue gas through the collected ash. Furthermore, the European system can distinguish between gaseous and aerosol SO 3 using deionized water procedures on various col

lection plates. The European SO 3 method system has been used extensively in the United States on a variety of coals with repeatable and reliable results. MITIGATION OF SO 3 EMISSIONS The mitigation of SO 3 has been an active area of research for many years. 13,23,44,45 This research has resulted in the development, re fi nement, and implementation of different techniques and methods for the successful mitigation
of SO 3 in the flue gases of fossil-fuel–fi red boilers. Re

cently, a guide that summarizes SO 3 mitigation options and their respective success in either full-scale or pilot testing has been written. 10 The mitigation options are
described below.

Alkali Addition into the Furnace The injection of alkali in the flue gas stream has been a method of SO 3 mitigation for almost 30 years. 44 The location in the flue gas stream and the delivery method of the alkali have been studied and tested depending on operating and site conditions. The addition of alkali into the furnace recently has been proven to be effective at the full scale. 30,39 However, the method of delivery and the effectiveness of the alkali used varies from site to site depending on speci fi c conditions. The addition of limestone to coal before pulverization for the control of SCR catalyst arsenic poisoning has been shown to be an effective method of furnace SO 3 control. Recent commissioning data 46 have shown at least Figure 7. CCS sampling train. 

### Srivastava, Miller, Erickson, and Jambhekar

758 Journal of the Air & Waste Management Association Volume 54 **June 2004**a 50% reduction in furnace SO 3 from limestone addition.The injection of alkaline sorbents (Ca- and Mg-based slurries) has been shown to be effective at controlling SO 3 emissions of the furnace. 39 The slurry injection method has successfully obtained SO 3 furnace conversion reduc

tions of 40

– 80% but has been found to be sensitive to injection location and elevation. The effects of the MgOsorbent slurries on SCR catalyst activity are currently under investigation. To date, no studies have measured the potential bene fit of SCR catalyst arsenic poisoning control by MgO sorbent injection. The addition or injection of alkali in the furnace does not in fluence the conversion rate of the SCR catalyst.

Alkali Injection after the Furnace The injection of other alkaline materials after the furnace/ economizer exit has been used for the control of SO 3 for
both APH corrosion and stack emissions. 10 The primarysorbents used are compounds such as hydrated lime, limestone, MgO, and sodium carbonate. The selection of a sorbent for a given site will depend on economic factors, such as availability and required SO 3 removal rates. Alkali injection has successfully removed between 40 and 90% of the SO 3 in the flue gas at various plants depending on the injected material and injection rate. 10 The sorbents
are introduced into the flue gas as either a dry powder or mixed with water to form slurry before injection. The location of injection in the flue gas stream varies. Plants with APH cold-end corrosion problems may elect to inject the sorbent before the APH; however, adequate APH cleaning equipment is required with this con figuration. In general, the common injection location for SO 3 con

trol is between the APH and the ESP. The injection of sorbent before the ESP must, however, consider the effect on particulate control. The ESP will have higher inlet mass loading, and the fly ash will have different resistivity characteristics. It has been reported that dry injection of hydrated lime has resulted in strong sparking and lower operating currents in the ESP during pilot-scale testing. 10

Ammonia Injection before the ESP The injection of NH 3 after the APH and before the ESP has
been shown to be  90% effective in the removal of SO 3 in full-scale application. 10 This method of mitigation results in the formation of (NH 4) 2 SO 4 and NH 4 HSO 4 salts in the ESP, depending on the NH 3 and SO 3 concentration Figure 8. CCS thimble holder. 

### Srivastava, Miller, Erickson, and Jambhekar

Volume 54 **June 2004** Journal of the Air & Waste Management Association 759ratios. The formation of NH 4 HSO 4 is expected when NH 3 to SO 3 molar ratios are less than 1; this formation tends to decrease the ESP particle loading caused by fly ash agglomeration. NH 3 injection before the ESP is used for fly ash conditioning to increase ESP performance caused by the agglomeration effects. With NH 3 to SO 3 molar ratios between 1 and 2, increased formation of (NH 4) 2 SO 4 is expected, with an increase in the particle loading of the ESP. The injection of NH 3 results in the adsorption of NH 3 by the fly ash. Because the fly ash will contain most of the injected NH 3 , the concentration may exceed acceptance limits for ash salability. Additional treatment of fly ash holding ponds and basins may be required if large amounts (

 30 ppmv) of SO 3 are being removed. The use
of NH 3 for SO 3 mitigation is practical on units equipped with SCRs, because NH 3 is used as the reagent and is readily available on site.

Fuel Switching and Blending
The fi ring of sub-bituminous coals typically results in low
SO 3 formation and emission rates. Consequently, switch

ing from fi ring bituminous to sub-bituminous coals can be a mitigation option. However, equipment and fuel cost factors often make such a change impossible. Many boiler systems do not have the capacity and the equipment to
accommodate the fi ring of sub-bituminous coal without major modi fi cations that make fuel switch economicallyunacceptable. Coal availability and costs also can constrain fuel switching. One possible solution is the blending of bituminous and sub-bituminous coals to create a blend that has fuel and ash characteristics favorable for
SO 3 emissions. This strategy is currently used for control

ling SO 2 emissions. When sub-bituminous coals are blended with bituminous coals, the overall S content of the fuel is reduced, resulting in a reduction of the SO 2 concentration in the flue gas as well as the conversion of
SO 2 to SO 3 in the furnace and SCR and, thereby, resulting
in an overall reduction in SO 3 . Also, the sub-bituminous coal ash contains large percentages of alkaline materials that further assist in the capture of SO 3 in the APH and
ESP.

Wet ESPsSimilar to dry ESPs, wet ESPs (WESPs) operate in a threestep process involving (1) charging of the entering particles; (2) collection of the particles on the surface of anoppositely charged surface; and (3) cleaning the collection surface. Both technologies employ separate charging and collection systems. However, the collecting surface in WESPs is cleaned with a liquid, in contrast to mechanical cleaning in dry ESPs. Consequently, the two technologies differ in the nature of particles that can be removed, the overall effi ciency of removal, and the design and maintenance parameters. 47 While dry ESPs are typically limited to power levels of 100

–500 W per 1000 cfm of flue gas, WESPs can operate with power levels as high as 2000W per 1000 cfm. Because of wet cleansing of the collection system, PM does not accumulate in the collection electrodes; this mitigates particle re-entrainment. Based on these factors, WESPs can collect sub-micron particles and acid mist very effi ciently. WESPs can be con figured for vertical or horizontal gas fl ows in tubular or plate designs. Tubular designs offer smaller footprints and, in general, are more effi cient than the plate type. WESPs can be integrated easily with a wet scrubber. In fact, integration of the WESP within the wet scrubber is a design option with many attractive features including a compact footprint; the ability to integrate the handling of the wash water and solids from the WESP with scrubber slurry, thereby avoiding the need for separate tank and blowdown system; and the ability to collect the fi ne H 2 SO 4 mist, which typically escapes the scrubber because of its very small droplet size. 47 In 1986, the fi rst commercial WESP application on a U.S. power plant took place when AES Deepwater, a 155-MW cogeneration plant fi ring petroleum coke as the primary fuel, was equipped with a WESP. With the WESP in operation, the plume opacity at the plant is generally
10% or less. 48 Recently, an up fl ow tubular design WESP has been

retro fit at Northern States Power Company’ s Sherco Station in a wet scrubber/WESP con figuration. Two more power plant applications are underway presently: (1) a 5000-cfm slipstream at Bruce Mans fi eld Station; and (2) a plate-type WESP for integration with Powerspan ’ s ECO technology to be demonstrated at First Energy’ s R.E. Burger plant. Tests at the Sherco Station (WESP retro fit to the outletsection of the wet scrubber) allowed the scrubber to maintain a 70% SO 2 reduction while keeping particulate emis

sions at 0.01 lb/10 6 Btu and opacity under 10%. Full conversion of all scrubber modules at the plant with WESPs is now underway. 49 The WESP at the Mans fi eld Station is achieving greater than 95% removal of SO 3 and
PM 2.5 and stack fl ow with near 0 opacity. 50

Changing the Operation of APH Increasing the heat transfer (or cooling of the flue gas) in the APH would appear to be a potentially viable strategy for removing some of the SO 3 /H 2 SO 4 in the APH. This, in turn, would lead to increased condensation of H 2 SO 4 in the APH and also to improved plant effi ciency. However, the dew point at the APH outlet is

 230 ° F (110 ° C), thereby limiting the SO 3 removal to

 90%. 30 On the other hand, the potential for corrosion in the APH and
downstream duct would increase with increased H 2 SO 4 

### Srivastava, Miller, Erickson, and Jambhekar

760 Journal of the Air & Waste Management Association Volume 54 **June 2004**condensation. Consequently, more frequent soot blowing may be required to control this corrosion. These factors would need to be considered when deciding to change the APH operation to mitigate SO 3 emissions. Data re fl ect that

 25% increase in H 2 SO 4 condensation may be possible by lowering the flue gas temperature at the APH exit by

 40

° F (22 ° C).

SUMMARY Formation and emissions of SO 3 /H 2 SO 4 potentially canlead to plant operation-related problems and environmental concerns. The formation of SO 3 is complex, de

pending upon fuel, operating parameters, and plant configuration, and understanding the parameters leading to excessive generation of SO 3 and subsequent formation of
H 2 SO 4 can assist in selections of practical control ap

proaches. Elevated SO 3 concentrations can lead to corro

sion, the formation of sul fite scale, and fouling and plugging of low-temperature plant components, and can add to the particle loading to control equipment. In some cases, elevated SO 3 concentrations can lead to the forma

tion of visible plumes at the stack exit or shortly downstream of the stack, resulting in noncompliance with local regulations.
SO 3 can be formed in the boiler during the combus

tion of S-bearing fuels or downstream, particularly in SCR
reactors. SO 3 /H 2 SO 4 can condense on low-temperature components and gets adsorbed by fly ash. Adsorption is much greater in the high alkaline ashes resulting from
sub-bituminous coal fi ring. SO 3 /H 2 SO 4 traditionally has been measured using extractive controlled condensation
methods. If needed, SO 3 /H 2 SO 4 emission can be mitigated us

ing a variety of methods. Injection of alkali materials into the furnace, either with the fuel or in slurry form, hasresulted in reductions of up to 80%. Post-furnace injection of alkali materials can achieve up to 90% reductionsbut can increase particle loadings and ash resistivity characteristics. NH 3 injection can also reduce SO 3 /H 2 SO 4 by

 90% and may result in increased particle loading to the downstream collection systems. In plants with adequate operational and equipment fl exibility, fuel switching and blending can be used to reduce formation and emissions
of SO 3 . WESPs are also an option for control of SO 3 /
H 2 SO 4 , and a variety of designs have been successfully demonstrated for collection of acid mists and opacity
control.

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About the Authors R.K. Srivastava and C.A. Miller are at the Offi ce of Research and Development, National Risk Management Research Laboratory, Research Triangle Park, NC. C. Erickson and R. Jambhekar are at Babcock Borsig Power, Inc., Worcester, MA. Address correspondence to: R.K. Srivastava, Offi ce of Research and Development, National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, U.S. Environmental Protection Agency, Research Triangle Park, NC, 27711; fax: (919) 541-0554; e-mail: srivastava.ravi@epa.gov. 

### Srivastava, Miller, Erickson, and Jambhekar

762 Journal of the Air & Waste Management Association Volume 54 **June 2004**